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WO2010009089A2 - Processus d'hydroconversion et d'hydrodésulfuration séquentiel de pétrole brut entier - Google Patents

Processus d'hydroconversion et d'hydrodésulfuration séquentiel de pétrole brut entier Download PDF

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Publication number
WO2010009089A2
WO2010009089A2 PCT/US2009/050486 US2009050486W WO2010009089A2 WO 2010009089 A2 WO2010009089 A2 WO 2010009089A2 US 2009050486 W US2009050486 W US 2009050486W WO 2010009089 A2 WO2010009089 A2 WO 2010009089A2
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Prior art keywords
reactor
metal
crude oil
group
catalyst
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PCT/US2009/050486
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English (en)
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WO2010009089A3 (fr
Inventor
Raheel Shafi
Esam Z. Hamad
Stephane Cyrille Kressmann
Ali Hussain Alzaid
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Saudi Arabian Oil Company
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Publication of WO2010009089A2 publication Critical patent/WO2010009089A2/fr
Publication of WO2010009089A3 publication Critical patent/WO2010009089A3/fr

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    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J35/00—Catalysts, in general, characterised by their form or physical properties
    • B01J35/60—Catalysts, in general, characterised by their form or physical properties characterised by their surface properties or porosity
    • B01J35/66—Pore distribution
    • B01J35/69—Pore distribution bimodal
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J35/00—Catalysts, in general, characterised by their form or physical properties
    • B01J35/60—Catalysts, in general, characterised by their form or physical properties characterised by their surface properties or porosity
    • B01J35/64—Pore diameter
    • B01J35/647—2-50 nm
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/02—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
    • C10G45/04—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
    • C10G47/02—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions characterised by the catalyst used
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G65/00—Treatment of hydrocarbon oils by two or more hydrotreatment processes only
    • C10G65/02—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only
    • C10G65/12—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only including cracking steps and other hydrotreatment steps
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/16—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of arsenic, antimony, bismuth, vanadium, niobium, tantalum, polonium, chromium, molybdenum, tungsten, manganese, technetium or rhenium
    • B01J23/20—Vanadium, niobium or tantalum
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/16—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of arsenic, antimony, bismuth, vanadium, niobium, tantalum, polonium, chromium, molybdenum, tungsten, manganese, technetium or rhenium
    • B01J23/24—Chromium, molybdenum or tungsten
    • B01J23/26—Chromium
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/70—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper
    • B01J23/74—Iron group metals
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/70—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper
    • B01J23/76—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper combined with metals, oxides or hydroxides provided for in groups B01J23/02 - B01J23/36
    • B01J23/84—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper combined with metals, oxides or hydroxides provided for in groups B01J23/02 - B01J23/36 with arsenic, antimony, bismuth, vanadium, niobium, tantalum, polonium, chromium, molybdenum, tungsten, manganese, technetium or rhenium
    • B01J23/85—Chromium, molybdenum or tungsten
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/70—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper
    • B01J23/76—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper combined with metals, oxides or hydroxides provided for in groups B01J23/02 - B01J23/36
    • B01J23/84—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper combined with metals, oxides or hydroxides provided for in groups B01J23/02 - B01J23/36 with arsenic, antimony, bismuth, vanadium, niobium, tantalum, polonium, chromium, molybdenum, tungsten, manganese, technetium or rhenium
    • B01J23/85—Chromium, molybdenum or tungsten
    • B01J23/88—Molybdenum
    • B01J23/883—Molybdenum and nickel
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/70—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper
    • B01J23/76—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper combined with metals, oxides or hydroxides provided for in groups B01J23/02 - B01J23/36
    • B01J23/84—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper combined with metals, oxides or hydroxides provided for in groups B01J23/02 - B01J23/36 with arsenic, antimony, bismuth, vanadium, niobium, tantalum, polonium, chromium, molybdenum, tungsten, manganese, technetium or rhenium
    • B01J23/85—Chromium, molybdenum or tungsten
    • B01J23/888—Tungsten
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/70—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper
    • B01J23/76—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper combined with metals, oxides or hydroxides provided for in groups B01J23/02 - B01J23/36
    • B01J23/84—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper combined with metals, oxides or hydroxides provided for in groups B01J23/02 - B01J23/36 with arsenic, antimony, bismuth, vanadium, niobium, tantalum, polonium, chromium, molybdenum, tungsten, manganese, technetium or rhenium
    • B01J23/85—Chromium, molybdenum or tungsten
    • B01J23/888—Tungsten
    • B01J23/8885—Tungsten containing also molybdenum

Definitions

  • the present invention relates to a process for the hydrodesulfurization of sour crude oils using a catalytic hydrotreating and desulfurization processes operating at moderate temperature and pressure and at reduced hydrogen consumption.
  • coke precursors can generally be very high.
  • coke precursors such as for example, asphaltenic plates
  • HDS hydro-desulfurization
  • deactivation of catalyst within a hydroprocessing unit typically occurs by one of two primary mechanisms: (1) metal deposition and (2) coke formation.
  • increasing the operating temperature of the hydroprocessing unit can help maintain catalyst performance; however, all process units have maximum temperature limits based upon the metallurgy of the process unit. These maximum temperatures limit the amount of time a catalyst can operate before requiring catalyst replacement, typically by either the regeneration of spent catalyst or the addition of fresh catalyst.
  • the replacement of spent catalyst with fresh catalyst can require the complete shutdown of a process unit in order to unload the deactivated spent catalyst and load fresh catalyst into the unit. This process unit downtime reduces the on-stream time and negatively impacts the economics of the process.
  • the method includes the steps of (a) contacting a crude oil feedstock with hydrogen gas to produce a hydrogen gas crude oil mixture; (b) contacting the hydrogen gas crude oil mixture with a hydroconversion catalyst in a first reactor maintained at a temperature of between about 400 0 C and 45O 0 C to produce an effluent having an asphaltene content of less than 5% by weight, wherein said hydroconversion catalyst includes a bimodal support material; (c) contacting the effluent from the first reactor with hydrogen gas to produce a effluent hydrogen gas mixture; (d) contacting the effluent hydrogen gas mixture with a desulfurization catalyst in a second reactor to produce an upgraded crude oil product having a reduced sulfur content and an increased API gravity, wherein said second reactor is maintained at a temperature that is less than the temperature that is maintained in the first reactor.
  • the hydroconversion catalyst can further include a base metal selected from the group consisting of a group VB metal, a group VIB metal and a group VIIIB metal and wherein the bimodal support material includes a first pore size having an average diameter of between about 6000 and 10000 Angstroms and a second pore size having an average diameter of between about 80 and 150 Angstroms.
  • the hydroconversion catalyst can also include a promoter metal, wherein the promoter metal is selected from the group consisting of a group HB metal, a group IVB metal and a group VIIIB metal, and wherein the promoter metal is present in an amount between about 1 and 3% by weight.
  • the hydroconversion catalyst can include a molybdenum base metal in an amount of between about 7.5 and 9% by weight, and a nickel promoter metal in an amount of between about 1 and 3% by weight.
  • the hydrodesulfurization catalyst can include a base metal selected from a group VB, VIB or VIIIB metal.
  • the hydrodesulfurization catalyst can also include a support material having an average pore size of between about 100 and 300 Angstroms.
  • the hydrodesulfurization catalyst can also include a promoter metal, wherein said promoter metal is selected from the group consisting of a group IIB metal, a group IVB metal and a group VIIIB metal, and wherein the promoter metal is present in an amount between about 1 and 3% by weight.
  • the hydrodesulfurization catalyst can include a molybdenum base metal in an amount of between about 9 and 11% by weight, and a nickel promoter metal in an amount of between about 2 and 3% by weight.
  • a method for upgrading crude oil includes the steps of (a) contacting a crude oil feedstock with hydrogen gas to produce a hydrogen gas crude oil mixture; (b) contacting the hydrogen gas crude oil mixture with a hydroconversion catalyst in a first reactor, wherein the hydroconversioh catalyst includes a support material having a bimodal pore size wherein the first pore size is between about 6000 and 10000 Angstroms and the second pore size is between about 80 and 150 Angstroms, and wherein the first reactor is maintained at a temperature of between about 400 0 C and 45O 0 C to produce an effluent having an reduced asphaltene concentration relative to the crude oil feedstock; (c) contacting the effluent from the first reactor with hydrogen gas to produce an effluent hydrogen gas mixture; and (d) contacting the effluent hydrogen gas mixture with a desulfurization catalyst in a second reactor to produce an upgraded crude oil product having a reduced sulfur content and an increased API gravity, wherein the second reactor
  • the hydroconversion catalyst can include a base metal selected from a group VIIIB metal and a bimodal support material, wherein the bimodal support material includes a first pore size having an average diameter greater than at least about 2000 Angstroms and less than about 15000 Angstroms and a second pore size having an average diameter of between about 50 and 250 Angstroms.
  • the hydrodesulfiirization catalyst can include a base metal selected from the group consisting of a group VB metal, a group VIB metal and a group VIIIB metal and a catalyst support material having an average pore size of between about 100 and 300 Angstroms.
  • Figure 1 is a diagram of one embodiment of a system for upgrading a whole crude oil.
  • Figure 2 is a diagram of another embodiment of a system for upgrading a whole crude oil.
  • Figure 3 shows the net conversion of the fraction of hydrocarbons having a boiling point greater than 540°C according to one embodiment of the process.
  • Figure 4 shows expected hydrodesulfurization according on one embodiment of the process.
  • Described is a process for the upgrading of whole crude oil which can include the use of a series of at least two reactors, for example, ebullating bed reactors.
  • the reactors employ different catalysts, and thus target different kinetic regimes, such as for example, the hydroconversion and hydrodesulfurization of whole crude oil feedstock.
  • the first reactor can include a hydroconversion catalyst that is selective for the conversion of high boiling hydrocarbons, particularly for the hydroconversion of hydrocarbon fractions having a boiling point greater than about 540 0 C. T ypically, the catalyst employed in the first reactor is selective for the conversion of hydrocarbon fractions having a boiling point greater than about 54O 0 C, and converts heavy material predominantly via thermal cracking.
  • the hydroconversion catalyst employed in the first reactor can be operated such that the asphaltene content of the effluent from the first reactor is reduced to less than 10% by weight of the effluent, preferably less than 8% by weight, and even more preferably less than about 5% by weight.
  • the asphaltene content of the effluent from the first reactor is reduced to less than 4% by weight of the effluent, preferably less than 3% by weight.
  • Use of hydroconversion catalysts in the first reactor, as noted above, is also advantageous because the catalyst used also acts as a pretreatment for the second stage.
  • the second reactor includes a catalyst that is selective for hydrodesulfurization of the whole crude feed.
  • the reactor conditions and the catalyst selected are operable to specifically remove sulfur from the liquid product, thereby producing an upgraded whole crude oil, or synthetic crude oil, having both a reduced sulfur content and an increased API gravity, as compared with the feedstock.
  • Figure 1 shows an exemplary method of operation where a whole crude oil feedstock is upgraded.
  • Whole crude oil feed 14 is contacted with hydrogen gas 12 at a pressure of between about 50 and 150 bar to create a crude oil/hydrogen gas mixture 16.
  • the hydrogen gas pressure is less than about 120 bar.
  • the hydrogen gas pressure is maintained between about 75 and about 125 bar, or between about 85 and 110 bar.
  • the hydrogen gas pressure is maintained at about 100 bar.
  • Crude oil/hydrogen gas mixture 16 is supplied to first reactor 18, preferably being supplied upwardly to a first ebullating bed reactor that includes a hydroconversion catalyst, although it is understood that other reactor designs can also be employed.
  • the hydroconversion catalyst employed in first reactor 18 is selective for the conversion of hydrocarbons having a boiling point greater than 540 0 C.
  • Fresh and/or regenerated hydroconversion catalyst can be added to first reactor 18 via line 20.
  • Spent catalyst can be withdrawn from the bottom of first reactor 18 via line 24, or by other known means.
  • spent catalyst withdrawn via line 24 can optionally be regenerated offline.
  • the catalyst regenerated offline can be resupplied back to first reactor 18.
  • fresh catalyst and regenerated catalyst can be supplied to the first reactor 18 via make-up line 24 to replace spent and/or withdrawn catalyst.
  • First reactor 18 can be operated at a temperature of between about 350 0 C and 450 0 C, and in certain embodiments can achieve conversion of up to about 50% of the hydrocarbon material having a boiling point above about 540 0 C in the crude oil feedstock. In other embodiments, the temperature can be maintained between about 375 0 C and 425°C. In yet other embodiments, the temperature can be maintained at about 400°C. Alternatively, the temperature can be maintained between about 400 0 C and 425°C. In certain embodiments, the first reactor is operated at a temperature greater than about 400 0 C. In certain embodiments, the effluent from the first reactor 18 has an asphaltene content of less than about 5 wt%.
  • Effluent 22 from first reactor 18 is contacted with hydrogen gas 26, and the resulting effluent-hydrogen gas mixture is fed to second reactor 28, preferably being fed upwardly to an ebullating bed reactor that includes a hydrodesulfurization catalyst, although it is understood that alternate reactor designs can also be employed.
  • Fresh and/or regenerated hydrodesulfurization catalyst can be added to second reactor 28 via line 30, and spent catalyst can be withdrawn from the second reactor via line 34.
  • Spent catalyst withdrawn from second reactor 28 can optionally be regenerated offline and resupplied to the second reactor.
  • second reactor 28 can be operated at a temperature of between about 350 0 C and 450 0 C.
  • second reactor 28 is operated at a temperature below about 400 0 C, and in certain other embodiments, the second reactor is operated at a temperatures below about 39O 0 C.
  • second reactor 28 is operated at a temperature between about 375° and 400 0 C.
  • Second reactor 28 can be operated at a pressure of between about 50 and 150 bar. In certain embodiments, second reactor 28 is operated at a pressure of between about 80 and 120 bar. In yet other embodiments, second reactor 28 is operated at a pressure of about 100 bar.
  • the final liquid product from second reactor 28 can be collected via line 32 as an upgraded crude oil product having a sulfur content of about 0.1 to 1 wt% and an API that has been increased by at least about 2 degrees, relative to the crude oil feedstock.
  • the first and second reactors can be any known vessels suitable for hydroconversion or hydrodesulfurization of a crude oil feedstock.
  • at least one of the reactors is an ebullating bed reactor.
  • the temperature of the first reactor is higher than the temperature of the second reactor.
  • the first reactor can be maintained at a temperature of between about 400° and 425 0 C and a pressure of between about 80 and 120 bar
  • the second reactor can be maintained at a temperature of less than about 400 0 C, and a pressure of about between about 80 and 120 bar.
  • the temperature of the first reactor is maintained at between about 405° and 420 0 C and the temperature of the second reactor is maintained between about 380° and 400 0 C.
  • the pressure of the first and second reactors is maintained at about 100 bar, the temperature of the first reactor is maintained at between about 410° and 420 0 C and the temperature of the second reactor is maintained at between about 380° and 390 0 C.
  • maintaining the temperature of the second reactor at less than about 400 0 C may improve the equilibrium of the reaction.
  • first reactor 18 and second reactor 28 can be operated at substantially similar reaction conditions with respect to operating temperatures and pressures. Alternatively, first reactor 18 and second reactor 28 can be operated at substantially different reaction conditions with respect to operating temperatures and pressures.
  • first reactor 18 can be an ebullating bed reactor charged with a hydroconversion catalyst, as previously described with respect to Figure 1. Catalyst is added to first reactor 18 via line 20 and removed from the reactor via line 24.
  • the effluent 22 from first reactor 18 can be supplied to inter-stage separator 40, which is operable to remove light gases, such as for example, H 2 S, NH 3 and hydrocarbons having fewer than five total carbon atoms, via line 41. Heavier compounds that are not removed by the inter-stage separator 40 can be mixed with hydrogen gas 26 and supplied via line 27 to second reactor 28.
  • second reactor 28 can include a desulfiirization catalyst. Fresh or regenerated catalyst can be added to second reactor 28 via line 30, and spent catalyst can be withdrawn via line 34. The resulting desulfurized crude can be collected from second reactor 28 via line 32. Reaction conditions for the first and second reactors shown in Figure 2 can be the same conditions as described with respect to Figure 1.
  • the effluent hydrogen gas mixture 42 from first reactor 18 can be quenched by a liquid stream.
  • the replacement rate of the hydrodesulfurization catalyst and the hydroconversion catalyst may be different. In certain other embodiments, the replacement rate of the hydrodesulfurization and hydroconversion catalysts can be the same.
  • the catalyst can include at least two metals, wherein a first metal is a base metal and a second metal is a promoter metal.
  • the base metal for the hydroconversion catalyst can be selected from a group VB, VIB or VIIIB metal, preferably selected from chromium, molybdenum, tungsten, iron, cobalt and nickel, and combinations thereof, more preferably selected from molybdenum and tungsten.
  • the base metal can be present in an amount between about 5 and 15% by weight, preferably between about 7 and 12% by weight, more preferably between about 7.5 and 9% by weight.
  • the hydroconversion catalyst can include a metal sulfide, wherein the metal is selected from the group VB, VIB or VIHB metals of the periodic table.
  • the promoter metal for the hydroconversion catalyst can be selected from a group IIB metal, a group IVA metal, or a group VIIIB metal.
  • Exemplary group HB metals include zinc, cadmium and mercury.
  • Exemplary group IVA metals include germanium, tin and lead.
  • Exemplary group VIIIB metals include iron, ruthenium, cobalt, nickel, palladium and platinum.
  • the promoter metal is selected from the group consisting of iron, cobalt, and nickel.
  • the promoter metal is nickel and is present in an amount between about 0.5 and 5% by weight, more preferably between about 1 and 3% by weight, even more preferably between about 1.5 and 2.5% by weight.
  • the base metal is selected from molybdenum, tungsten and combinations thereof, and is present in an amount between about 7.5 and 9% by weight, and the promoter metal is nickel, and is present in an amount of between about 1 and 3% by weight.
  • the support material for the hydroconversion catalyst is typically more acidic than the support for the hydrodesulfurization catalyst.
  • the support material for the catalysts for both the hydroconversion and hydrodesulfurization can be prepared by either precipitation or mulling. Precipitation and mulling are known processes for the formation of support materials.
  • Exemplary support materials for the hydroconversion and hydrodesulfurization catalysts can include zeolites, amorphous silica-alumina and alumina, which can be mulled or kneaded to form a paste, which can be subsequently formed and dried for the formation of the support material. The mulled or kneaded products can further undergo thermal treatment, resulting in more intimate contact between the components.
  • the support material hydroconversion catalyst typically has a greater concentration of co-mulled amorphous silica-alumina and zeolite, and is typically more acidic, as compared with the support material for the hydrodesulfurization catalyst.
  • the catalyst support material can also include additional components, including binders (e.g., silica or alumina sol suspension), die lubricants (e.g., graphite or stearic acid), and pore forming additives (e.g., wood flower, starch, organic polymers, or carbon fibers).
  • binders e.g., silica or alumina sol suspension
  • die lubricants e.g., graphite or stearic acid
  • pore forming additives e.g., wood flower, starch, organic polymers, or carbon fibers.
  • Pore size distribution of the support material can be affected by the drying, forming and calcining of the precipitate or formed mulled paste. The final shape and size of the pores of the support material is typically determined during the forming step and can include, for example, extrudates, spheres (beads) or pellets. Size and shape are typically determined and selected based upon the need for high activity, acceptable mechanical strength, and the type
  • the support material for the hydroconversion catalyst preferably has a bimodal structure having a first pore size of greater than about 2000 Angstroms, and less than about 15,000 Angstroms, preferably between about 6000 and 10,000 Angstroms and a second pore size of between 50 and 250 Angstroms, preferably about 80 and 150 Angstroms.
  • the first mesoporous pores allow larger asphaltene molecules to enter into the pore and be converted by cracking.
  • the smaller microporous pores are suitable for the conversion of smaller molecules (i.e., molecules smaller than asphaltenes), and in certain embodiments, may also result in some hydrotreatment of the hydrocarbon molecules.
  • the hydroconversion catalyst can include more than one metal or metal sulfide.
  • the hydroconversion catalyst metal is present in an amount of between about 0 and 25% by weight. In other embodiments, the hydroconversion catalyst metal is present in an amount between about 1 and 20% by weight.
  • the hydroconversion catalyst can be supported on any known support material, including but not limited to, ⁇ -alumina and/or ⁇ -alumina and silica in the form of extrudates, spheres, cylinders or pellets, or the like.
  • only one catalyst selected from the hydrodesulfurization catalyst and the hydroconversion catalyst includes a group VIIIB metal.
  • the hydrodesulfurization and hydroconversion catalysts have a nearly identical metal content.
  • the amount of base metal in the hydroconversion catalyst is greater than the amount of base metal in the hydrodesulfurization catalyst.
  • the hydrodesulfurization catalyst used in second reactor 28 can be selected to preferably remove sulfur through hydrodesulfurization reactions, while at the same time, minimizing thermal cracking.
  • the hydrodesulfurization catalyst can include a base metal selected from a group VB, VIB or VIIIB metal, preferably selected from chromium, molybdenum, tungsten, iron, cobalt and nickel, and most preferably molybdenum.
  • the hydrodesulfurization catalyst can include more than one metal.
  • the catalyst can include at least two metals, wherein a first metal is a base metal and a second metal is a promoter metal.
  • the base metal present in the hydrodesulfurization catalyst can be present in an amount of between about 0 and 25% by weight. In other embodiments, the metal can be present in an amount between about 1 and 20% by weight.
  • the base metal is present in an amount between about 5 and 15% by weight, preferably between about 8 and 12% by weight, and even more preferably in an amount of between about 9 and 11% by weight.
  • the desulfurization catalyst can include a metal sulfide selected from the group VB, VIB and VIIIB metals of the periodic table, which can be supported on any known support material, such as for example, but not limited to, ⁇ -alumina and/or ⁇ -alumina and silica in the form of extrudates, spheres, cylinders or pellets.
  • the hydrodesulfurization catalyst can include a promoter metal.
  • the promoter metal can be selected from a group IIB metal, a group FVA metal, or a group VIIIB metal.
  • Exemplary group IIB metals include zinc, cadmium and mercury.
  • Exemplary group IVA metals include germanium, tin and lead.
  • Exemplary group VIIIB metals include iron, ruthenium, cobalt, nickel, palladium and platinum.
  • the promoter metal is selected from the group consisting of iron, cobalt, and nickel.
  • the promoter metal can be present in an amount between about 0.5 and 5% by weight, more preferably between about 1 and 3% by weight, even more preferably between about 2.5 and 3% by weight.
  • the support for the hydrodesulfurization catalyst has a pore size having a distribution range of between about 75 and 500 Angstroms, preferably between about 100 and 300 Angstroms.
  • the catalyst support has a monomodal pore size, resulting in a relatively uniform pore size distribution.
  • the pore size of the desulfurization catalyst allows for sulfur containing molecules to enter the pores and be desulfurized, enabling for a maximization of the surface area available for desulfurization, thereby allowing for a maximum number of active sites to contact the sulfur containing molecules.
  • the desulfurization catalyst support material has a lower acidity, having co-mulled amorphous silica-alumina and zeolite being present in larger amounts than is found in the support material for the hydroconversion catalyst.
  • the whole crude oil feedstock can be first supplied to a reactor that includes a hydrodesulfurization catalyst according to the present invention, and then supplied to a reactor that includes an appropriate hydroconversion catalyst according to the present invention.
  • the whole crude oil prior to supplying the crude oil to the hydroconversion reactor, can be separated into two initial fractions, a first whole crude oil fraction having a maximum boiling point of not greater than about 25O 0 C, and a second whole crude oil fraction containing the balance of the whole crude oil (i.e., material having a boiling point greater than about 25O 0 C).
  • the first whole crude oil fraction can be removed from the whole crude oil processes such that the first whole crude oil fraction is supplied to a separate reaction zone for the removal of sulfur, and can then be recombined with the second reactor effluent 32 to form a final total liquid product having a total reduced sulfur content of preferably between about 0.1 and 1 wt%.
  • the first whole crude oil fraction can optionally be recombined with the effluent from the first reactor 22, contacted with hydrogen gas 26, and their supplied to the second reactor 28 as a mixture consisting of whole crude oil having a boiling point of less than about 25O 0 C and hydrogen gas.
  • the system was maintained at a total hydrogen pressure of about 100 bar and the hydrogen gas to hydrocarbon feedstock ratio was maintained at a ration of about 800 liters of hydrogen per liter of Arab heavy crude feedstock.
  • the catalyst system was maintained at a temperature of between about 400 0 C and 42O 0 C.
  • the heavy crude oil was supplied with hydrogen gas to a first reactor charged with a hydroconversion catalyst, and the effluent from the first reactor was then supplied, along with hydrogen gas, to a second reactor charged with a hydrodesulfurization catalyst.
  • the liquid hourly space velocity (LHSV) for the first and second reactors were approximately 0.5 hr "1 .
  • Net conversion of the fraction having a boiling point greater than 54O 0 C is shown in Figure 3, wherein a net conversion of the crude having a boiling point of greater than 540 0 C of approximately 45 wt% is achieved.
  • the predicted performance of the hydrodesulfurization reaction in the second reactor is provided in Figure 4, which predicts that approximately 86 wt% hydrodesulfurization is achieved.

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Abstract

L'invention concerne un procédé permettant d'éliminer le soufre de pétroles bruts au moyen d'un processus d'hydrotraitement catalytique fonctionnant à température et la pression modérée et avec une consommation d'hydrogène réduite. Ce processus produit du pétrole brut adouci, outre une densité brute réduite, possède un contenu en soufre compris entre environ 0,1% et 1,0% en poids. Le procédé utilise au moins deux réacteurs en série, le premier réacteur comprenant un catalyseur d'hydroconversion et le second réacteur comprenant un catalyseur de désulfuration.
PCT/US2009/050486 2008-07-14 2009-07-14 Processus d'hydroconversion et d'hydrodésulfuration séquentiel de pétrole brut entier WO2010009089A2 (fr)

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